Central circulation completion system

ABSTRACT

A completion system comprises a christmas tree ( 10 ) mounted on a wellhead housing ( 11 ), a tubing hanger ( 12 ) landed in the tree or wellhead housing, the wellhead housing ( 11 ) being mounted on a casing string ( 100 ) and a tubing string ( 14 ) being suspended from the tubing hanger within the casing string; wherein, in use, the annulus defined between the tubing ( 14 ) and the casing ( 100 ) serves as a production bore. A second tubing string ( 98 ) is expanded into sealing engagement with the casing string ( 100 ) over at least a portion of their lengths. The annulus normally used to provide well service functions is thus eliminated. Well servicing is instead provided via the tubing string ( 14 ), which may be coiled tubing.

INVENTION BACKGROUND

[0001] Traditionally, a subsea christmas tree provides pressure control of a well completion system that comprises a centrally located well bore and a surrounding annulus conduit. The centrally located well bore is typically used for the extraction of reservoir hydrocarbons and is referred to as the production bore. The annulus conduit is typically used to service the well, for example allowing the circulation of fluids during well start up and shut down. During the production phase of the well, the annulus is often redundant and is monitored for pressure build up indicating a possible production tubing or packer leak from the production bore. Some wells employ the annulus for gas lift. Gas is pumped down the annulus and enters the production bore at specific locations thereby reducing the density and viscosity of the produced fluids. Electrical, optical and hydraulic service lines are also typically routed through the annulus for powering and control of downhole equipment such as valves and pumps, or for data transmission from downhole sensors. Chemical injection lines are likewise routed through the annulus.

[0002] Recent developments in expandable casing technology and reeled tubular technology dictate completion designs having decreased diameter well casing tubulars located external to the production tubing. The radial gaps between the tubulars are likewise reduced.

SUMMARY OF THE INVENTION

[0003] The present invention enables still further benefits to be gained from expandable casing technology. According to the invention, there is provided a completion system comprising a christmas tree mounted on a wellhead housing, a tubing hanger landed in the tree or wellhead housing, the wellhead housing being mounted on a casing string and a tubing string being suspended from the tubing hanger within the casing string; characterised in that, in use, the annulus defined between the tubing and the casing serves as a production bore and the tubing serves as a well service conduit; a second tubing string being expanded into sealing engagement with the casing string over at least a portion of their lengths. A second or outer tubing string surrounding that suspended from the tubing hanger may therefore be expanded to contact the production casing so that a seal is effected between these two tubulars, thereby eliminating the annulus conduit. The annulus conduit may only be absent at the base of the well in the case of a tapered well construction but uniform diameter, non-tapering wells are also possible in which the annulus is totally eliminated.

[0004] In this circumstance, it is no longer possible to circulate fluids in the well via the annulus and the central tubing string suspended from the tubing hanger performs the function that the annulus traditionally performs. The annulus conduit defined between the two tubing strings is now used for production. This has a significant impact on the configuration of the completion equipment, especially the tree. Further preferred features and advantages of the invention are in the dependent claims and the following description of preferred embodiments, made with reference to the drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

[0005]FIG. 1 is a diagrammatic representation of a first completion system embodying the invention, shown during installation/testing;

[0006]FIG. 2 corresponds to FIG. 1 but shows the system in production mode;

[0007]FIG. 3 diagrammatically represents a tubing hanger such as may be used in the system of FIG. 1;

[0008]FIGS. 4 and 5 show an alternative tubing hangers;

[0009]FIGS. 6, 8, 10 and 12 are diagrams of second, third, fourth and fifth embodiments of the completion system respectively, all shown during installation/testing;

[0010]FIGS. 7, 9, 11 and 13 correspond to FIGS. 6, 8, 10 and 12 respectively, but show the system in production mode;

[0011]FIG. 14 shows a modification of the embodiment of FIG. 13;

[0012]FIG. 15 is a diagram of a first casing program that may be used in conjunction with the completion system of the invention;

[0013]FIG. 16 corresponds to FIG. 15 but diagrammatically indicates a liner, an outer tubing string and completion riser run into the casing;

[0014]FIG. 17 is a diagram of the interface between the tree, wellhead housing and outer tubing hanger of the completion system of FIG. 16;

[0015]FIG. 18 corresponds to FIG. 17 but diagrammatically indicates a central circulation tubing string and liner top isolation valve installed in the well;

[0016]FIG. 19 is a diagrammatic cross-section through the central circulation tubing;

[0017]FIG. 20 is a diagram of a second casing program that may be used in conjunction with the completion system of the invention;

[0018]FIG. 21 corresponds to FIG. 20 but diagrammatically indicates a liner and outer tubing run into the well;

[0019]FIGS. 22 and 23 show tubing expansion operations;

[0020]FIG. 24 is a diagram of the interface between the tree, wellhead housing and outer tubing of the completion system of FIG. 21;

[0021] FIGS. 25 to 27 show modifications of FIG. 24;

[0022]FIG. 28 is a diagram of a third casing program that may be used in conjunction with the completion system of the invention;

[0023]FIG. 29 corresponds to FIG. 28 but diagrammatically indicates a liner, production casing and outer tubing run into the well, and

[0024]FIG. 30 is a diagram of the interface between the tree, wellhead housing and outer tubing hanger of the completion system of FIG. 22.

DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0025] The preferred completion system includes a subsea christmas tree configuration that will allow the installation of a centrally located service conduit. The preferred well, construction also comprises the following components that are typically used in completions and accordingly the subsea tree design provides the appropriate interfacing equipment:

[0026] SCSSV or functional equivalent

[0027] Downhole chemical injection

[0028] Gas lift mandrels

[0029] Downhole instrumentation, e.g. pressure and temperature gauges

[0030] The central service conduit provided by a central coiled tubing string is preferably replaceable with minimum impact on the installed second or outer production tubing and subsea christmas tree equipment. The outer tubing string is terminated at the wellhead housing (either with or without a tubing hanger) and the tree seals to the wellhead housing with a seal stab.

[0031] Referring to FIG. 1, coiled tubing 14 is suspended from a coiled tubing hanger 12 in a horizontal christmas tree 10. The tree 10 is locked and sealed to a wellhead housing 11. No SCSSV is included in the system. For installation, the coiled tubing hanger 12 has a lock profile 16 by which it is attached to an installation test tool 18. A central circulation/service valve 20 is situated in the coiled tubing hanger 12 for controlling fluid flows from/to the coiled tubing 14. The coiled tubing hanger 12 is landed in a vertically extending through bore 15 in the tree 10. The tubing hanger 12 is sealed and locked to the tree as schematically indicated, by annular seal 22 and lock profile 24. Remote wet mate couplers 26 allow downhole service and control lines 28 to be connected to corresponding lines 30 in the installation test tool 18 and its installation string 32. The outside diameters of the coiled tubing hanger 12, installation test tool 18 and installation string 32 are compatible with the drift of a monobore completions riser which has, for example, a bore diameter of 17.1 mm (6.75″).

[0032] A production conduit 34 intersects with the through bore 15 below the tubing hanger seal 22. A production master valve 36 and a production wing valve 38 are provided in the production conduit 34. A pressure cap 40 is optionally installed on a wing outlet 42 of the tree 10 at the stage of installation and subsequent flow test. For flow testing, a production bypass conduit 44 containing a valve 46 extends between the production conduit 34 to the through bore 15 above the tubing hanger seal 22. A service/circulation conduit 48 intersects with the through bore 15 above the tubing hanger seal 22. The conduit 48 contains a valve 50 of equivalent function to the annulus wing valve of a “standard” horizontal tree. However, rather than communicating with a production tubing/production casing annulus as is conventional, the service/circulation conduit 48 is connected to the upper end of the coiled tubing 14. A crossover conduit 45 containing a crossover valve 47 connects the bypass conduit 44 (and/or the production conduit 34 between the valves 36, 38) to the circulation/service conduit 48.

[0033] The installation test tool 18 is connected between the coiled tubing hanger 12 and the installation string 32. Upper and lower seals 52, 54 seal a lower end of the installation test tool 18 within the tree through bore 15. A conduit 56 in the installation test tool 18 has a side outlet positioned between the seals 52, 54 for communication with the production bypass conduit 44, and an upper end in communication with a riser conduit 58 in the installation string 32. During flow testing, production fluid may therefore be led to the surface rig or vessel through the installation test tool interior and the riser conduit 58.

[0034] The lower end of the installation test tool 18 also has a central bore 60 in communication with the coiled tubing interior via the central circulation/service valve 20. A side outlet 61 leads from the bore 60 to the circulation/service conduit 48. A workover conduit 62 containing a workover valve 64 extends from the circulation/service conduit 48 to the tree through bore 15 at a point above the installation test tool upper seal 52. The other end of the installation test tool 18 comprises an upwardly extending spool 66 through which runs the conduit 56. A BOP 68 is attached to the upper end of the tree 10. Pipe rams 70 in the BOP 68 can be closed and sealed about the installation test tool spool 66, thereby sealingly connecting the workover conduit 62 to a choke/kill line 72 of the BOP.

[0035] The installation test tool also allows controls to be hooked up to the down-hole lines 28 and for operation of the circulation/service valve 20 in the coiled tubing hanger 12. Besides the remote subsea mateable couplers 26 to the top of the coiled tubing hanger 12, the installation test tool 18 also includes further remote subsea mateable couplers 74 to the base of the installation string 32.

[0036] The installation string 32 is latched and sealed to the top of the installation test tool 18 by a remotely operable connector 76 providing emergency disconnect capability. A monobore completions riser 78 is connected to the upper end of the BOP 68 by a lower marine riser package 80 which also provides for emergency disconnection. When disconnected, any fluids present in the riser conduit 58 are retained by a valve 82. The couplers 74 connect the control lines 30 in the installation test tool 18 to a controls umbilical 84 attached to the installation string 32.

[0037]FIG. 2 shows the tree in production mode. An internal tree cap 86 is installed through the BOP 68 in place of the installation test tool 18 and installation string 32. The BOP 68 is then removed. The tree cap 86 locks and seals to the tree bore 15 above the production conduit 34 intersection as schematically illustrated by locking profile 88 and seal 90. Remote subsea mateable couplers 26 are again provided for hook up of control lines to the central circulation/service valve 20 in the coiled tubing hanger 12 and to the downhole lines 28. A controls cap 92 with remote wet mate couplers 94 connects the control lines to a jumper 96. The central bore 60 and side outlet of the installation test tool are reproduced in the tree cap 86 to provide fluid communication between the coiled tubing interior and the circulation/service conduit 48.

[0038] The completion system illustrated in FIGS. 1 and 2 satisfies accepted double barrier pressure containment philosophy/industry practice. It provides communication to multiple down-hole electrical and hydraulic service lines, either via a controls umbilical run with the installation string, or via a controls cap and jumper in production mode. A central coiled tubing string 14 is suspended in the well, to provide a means of well circulation for well startup and well kill. It also provides a means for readily installing or removing (eg for servicing and repair) downhole equipment such as valves, pumps, gas lift and chemical injection mandrels and downhole instrumentation. This can be installed/replaced without disturbing the outer production tubing and tree.

[0039] The central coiled tubing string 14 is suspended within an outer tubing string 98 which is expanded into sealing contact with surrounding production casing 100 and the wellhead housing 11. The need for tubing hangers and packers may thus be eliminated. If a tubing hanger is used to suspend the outer tubing string 98 which has its lower end expanded into contact with the production casing, the outer tubing hanger is landed in the wellhead 11 because the outer tubing 98 is permanently attached to the other well tubulars and cannot be retrieved. Landing the outer tubing hanger in the tree 10 would therefore prevent (or at least make difficult) the recovery of the tree. If tubing corrosion occurs, a new (thin wall) liner tubing can be expanded into place inside the old outer tubing.

[0040] The use of expandable well tubulars also results in a more gradually tapering, or even uniform diameter, well. Thus the upper tubulars and completion equipment are of reduced size and weight compared to conventional wells of equivalent depth, giving materials savings and reduced operational costs. The marine riser system/BOP stack used at installation only needs a bore similar to a completions riser. Therefore it is very similar to a lightweight intervention system. Faster drill penetration rates can be achieved and the use of lower cost vessels with lower lift capacity is made possible.

[0041] Flow tests may be conducted via the installation string and workover access is provided via the coiled tubing string. The tree has a similar cost and complexity to known horizontal trees. No subsea test tree is needed during installation and workover. There is potential to adapt the system for a dual zone completion, for the use of ESP's, or for downhole separation. The effective production tubing size can be reduced as the well matures, by increasing the diameter of the coiled tubing, or a velocity string can be fitted. The completion system offers improved control of well circulation via the subsea tree for well kill or gas lift applications.

[0042] FIGS. 3-5 illustrate various alternatives for the coiled tubing hanger configuration. FIG. 3 shows a single body coiled tubing hanger 12 with an integral ball valve 20 and hydraulic actuator. Down hole control lines 102 pass through the hanger body and are connected to control lines 104 external to the coiled tubing 14 via couplers 106. The down hole controls lines are therefore exposed to produced fluids and mechanical damage during the trip in the hole. The remote mateable couplers 26 must be made very small.

[0043]FIG. 4 shows a single, multi-pin, self orienting subsea mateable connector 108 instead of the multiple connectors 26. This system is particularly suitable if the down hole lines 104 are all of the same type, e.g electrical, optical or hydraulic. It is less suitable if there is a combination of different line types.

[0044]FIG. 5 shows a split hanger arrangement in which the coiled tubing hanger comprises two separable parts 12 a, 12 b, joined by a seal stab 110. The lower part 12 b is prefabricated as part of the coiled tubing string and the service line couplers 112 are factory tested. The lower part 12 b is assembled to the upper part 12 a at the drill floor. This design may have multiple single-pin subsea mateable couplers as shown, or a multi-pin connector similar to 108, FIG. 4.

[0045]FIG. 6 shows a modification of the system of FIG. 1, in which the coiled tubing hanger 12 has a blind top, i.e. no vertical through bore is provided. Comparing with the FIG. 1 embodiment, in FIG. 6 the central circulation/service valve 20 has been moved from the coiled tubing hanger 12 to the circulation/service conduit 48 in the tree 10. The workover conduit 62 still joins the central circulation/service conduit 48 between the valve 20 and the wing valve 50. The lower seal 54 on the installation test tool 18 has been eliminated and an additional upper seal 114 provided on the coiled tubing hanger 12. A side outlet 116 in the tubing hanger 12, analogous to the installation test tool side outlet 61 in FIG. 1, communicates with the circulation/service conduit 48, between the tubing hanger upper and lower seals 114, 22. In other respects, the FIG. 6 arrangement is structurally and functionally similar to that of FIG. 1.

[0046]FIG. 7 shows the system of FIG. 6 in production mode. It is analogous to FIG. 2, but having a simplified internal tree cap 86, as the bore 60 and side outlet 61 are eliminated. A controls cap 92 and a controls jumper 96 are again provided.

[0047]FIG. 8 shows a third embodiment, similar to FIG. 6, except that a second production bypass valve 43 is provided in the production bypass conduit 44, in series with the valve 46. This enables the tree cap 86 to be eliminated in production mode (FIG. 9), as the valve 43 can serve as a second pressure barrier in series with the valve 46, when the production master valve 36 is open. If desired, a secondary lockdown device 118 can be provided for the coiled tubing hanger 12 in production mode. The controls cap 92 and couplers 94 interface directly with the coiled tubing hanger 12. The embodiment of FIGS. 1 and 2 may be modified in similar manner.

[0048]FIG. 10 shows a further modification of the FIG. 6 embodiment. The production bypass conduit 44 and bypass valve 46 have been eliminated, likewise the side outlet in the installation test tool 18 below the seal 52. Instead, the coiled tubing hanger 12 is provided with flow by slots or a flow by conduit 120 extending from the annulus defined between the tubing strings 14, 98 below the tubing hanger 12, to the tree through bore 15 above the tubing hanger 12. The installation test tool 18 no longer interfaces with the tubing hanger lock profile 16. Instead, a separate tubing hanger running tool (not shown), is used to install the tubing hanger 12. Upper and lower swab valves 122, 124 (e.g. large diameter gate valves) are provided in the tree through bore 15 between the installation test tool 18 and the coiled tubing hanger 12. In production mode (FIG. 11) these swab valves are closed to provide a double pressure barrier, so that no tree cap is needed. The workover conduit 62 extends from the circulation/service conduit, to the through bore 15 above the installation test tool lower seal 52, for fluid communication with BOP choke/kill lines 72, as previously described. Hook up to the downhole service lines 28 is by means of horizontal penetrators in the tree 10, which interface with the coiled tubing hanger 12. The coiled tubing hanger 12 is effectively pressure balanced and theoretically needs no lock down. The lower end of the coiled tubing string 14 is not fixed so thermal expansion does not provide an upthrust. Notional lock down is provided by the horizontal penetrators 126 from the tree 10.

[0049]FIG. 12 shows a modification of the FIG. 10 embodiment, for which the installation process is similar to a conventional christmas tree, in that a BOP stack is not used on the tree. The BOP stack and marine riser are removed from the wellhead 10 prior to tree installation and a lower riser package 128, emergency disconnect package 130 and an open water riser 132 are used for the coiled tubing hanger installation and flow test. A sealed connection interface 134 is provided for coupling the workover conduit 62 in the tree 10 to a port 136 in the lower riser package 128, of equivalent function to a conventional lower riser package annulus port. An installation test tool is not required for installing and flow testing the completion. The lower riser package128/emergency disconnect package 130 system may have a controls umbilical 142, for example connectable to the tree 10 via remote wet mate couplers 144, for hook up to the tree valves and to the downhole service lines 28 via the horizontal penetrators 126. Installation and recovery of the coiled tubing string may be carried out from a lightweight intervention vessel, without the use of a BOP. The lower riser package includes upper and lower valves 138, 140 (for example large bore gate valves) at least one of which may, if required in an emergency, be used to shear the coiled tubing string. FIG. 13 shows the tree in production mode with the EDP/LRP and riser removed and the swab valves 122, 124 closed above the coiled tubing hanger 12.

[0050] Finally, FIG. 14 corresponds to FIG. 13 but shows a modification in which the production conduit 34 intersects with the tree through bore above the coiled tubing hanger 12, rather than below it.

[0051] Table 1 sets out barrier matrices for the completions described above, for various procedures and conditions. Abbreviations BOP Blowout preventer CSV Circulation/service valve CT Coiled tubing CTH Coiled tubing hanger CXT Conventional tree HXT Horizontal tree ITC Internal tree cap ITT Installation test tool LRP Lower riser package LSV Lower swab valve LTIV Liner top isolation valve PBV Production bypass valve PMV Production master valve PWV Production wing valve SSTT Subsea test tree TH Tubing hanger USV Upper swab valve ITC Internal tree cap WOV Workover valve

[0052] TABLE 1 (follows) COMPLETION TYPE FIGS. 1 and 2 FIGS. 6 and 7 FIGS. 8 and 9 FIGS. 10 and 11 PROCEDURE 1^(st) Barrier 2^(nd) Barrier 1^(st) Barrier 2^(nd) Barrier 1^(st) Barrier 2^(nd) Barrier 1^(st) Barrier 2^(nd) Barrier Foundation Drill 36″ hole N/A N/A N/A N/A N/A N/A N/A N/A Run and cement 30″ conductor N/A N/A N/A N/A N/A N/A N/A N/A and LP housing Drill 12-1/4″ hole N/A N/A N/A N/A N/A N/A N/A N/A Drilling N/A N/A Run and cement 6″ casing and N/A N/A N/A N/A N/A N/A N/A N/A wellhead housing Run BOP stack and marine riser N/A N/A N/A N/A N/A N/A N/A N/A Drill 8″ hole Fluid BOP Fluid BOP Fluid BOP Fluid BOP Run 6″ liner Fluid BOP Fluid BOP Fluid BOP Fluid BOP Drill 8″ hole Fluid BOP Fluid BOP Fluid BOP Fluid BOP Run 6″ liner Fluid BOP Fluid BOP Fluid BOP Fluid BOP Drill 8″ hole Fluid BOP Fluid BOP Fluid BOP Fluid BOP Run 6″ liner Fluid BOP Fluid BOP Fluid BOP Fluid BOP Drill 8″ hole N/A N/A N/A N/A N/A N/A N/A N/A Run 6″ liner and lower N/A N/A N/A N/A N/A N/A N/A N/A completion with LTIV Run 5″ upper completion and N/A N/A N/A N/A N/A N/A N/A N/A expand onto the 6″ liner Set casing plugs Caing plug Fluid Casing plug Fluid Casing plug Fluid Casing plug Fluid Tree Installation Retrieve BOP Caing plug Fluid Casing plug Fluid Casing plug Fluid Casing plug Fluid Run HXT Caing plug Fluid Casing plug Fluid Casing plug Fluid Casing plug Fluid Run BOP/LRP Caing plug Fluid Casing plug Fluid Casing plug Fluid Casing plug Fluid Completion Drill out/remove casing plugs N/A N/A N/A N/A N/A N/A N/A N/A Drill 8″ hole Fluid BOP Fluid BOP Fluid BOP Fluid BOP Run 6″ liner and lower Fluid BOP Fluid BOP Fluid BOP Fluid BOP completion with LTIV Pull HXT bore protector LTIV Fluid/BOP LTIV Fluid/BOP LTIV Fluid/BOP LTIV Fluid/BOP Run 5″ upper completion LTIV Fluid/BOP LTIV Fluid/BOP LTIV Fluid/BOP LTIV Fluid/BOP (outer tubing) and expand onto the 6″ liner Run CTH, lock and test LTIV Fluid/BOP/ LTIV Fluid/BOP/ LTIV Fluid/BOP/ LTIV Fluid/BOP CTH CTH CTH CTH Flow Test Circulate to lighter fluid LTIV CSV LTIV CSV LTIV CSV LTIV CSV Overpressure the LTIV and PWV Pressure Cap PWV Pressure cap PWV Pressure Cap PMV PWV flow test the well CSV WOV CSV WOV CSV WOV CSV WOV ITT BOP ITT BOP ITT BOP ITT BOP Isolate well at HXT PMV PWV PMV PBV PMV PBV USV LSV Run ITC CTH ITC and CTH ITC and N/A N/A N/A N/A BOP BOP Run CTH 2ary lockdown N/A N/A N/A N/A CTH BOP N/A N/A Pull BOP/LRP CTH ITC CTH ITC CTH upper CTH lower USV LSV seal seal Install controls cap by ROV CTH ITC CTH ITC CTH upper CTH lower N/A N/A seal seal Produce to flow lines CTH ITC CTH ITC CTH upper CTH lower USV LSV seal seal Tubing access workover with BOP Pull controls cap CSV ITC CTH ITC CTH upper CTH lower N/A N/A seal seal Pull ITC CSV BOP CTH BOP CTH BOP N/A N/A Run LRP/ N/A N/A N/A N/A N/A N/A USV LSV BOP + marine riser Run ITT CSV BOP CTH BOP CTH BOP USV LSV Circulate the well to kill weight Fluid CSV + BOP Fluid CTH + BOP Fluid CTH + BOP Fluid BOP Pull CTH Fluid BOP Fluid BOP Fluid BOP Fluid BOP Replace CTH Fluid BOP Fluid BOP Fluid BOP Fluid BOP Circulate the well to light weight CSV CSV + BOP CTH CSV + BOP CTH BOP USV LSV Pull ITT CSV CSV + BOP CTH CSV + BOP CTH BOP USV LSV Run ITC CSV ITC CTH ITC CTH BOP N/A N/A Pull BOP stack + CSV ITC CTH ITC CTH upper CTH lower USV LSV marine riser/LRP seal seal Install controls cap CSV ITC CTH ITC CTH upper CTH lower N/A N/A seal seal Tubing access workover with LWI Vessel Similar to above Outer tubing retrieval workover with BOP Assumed to be impossible due to tubing being expanded onto previous casing COMPLETION TYPE FIGS. 12, 13 and 14 PROCEDURE 1^(st) Barrier 2^(nd) Barrier COMMENTS Foundation Drill 36″ hole N/A N/A Run and cement 30″ conductor N/A N/A Assuming that well and LP housing foundation is needed as per Drill 12-1/4″ hole N/A N/A Drilling Run and cement 6″ casing and N/A N/A HP housing has 6-8½″ nom. wellhead housing bore and no casing hanger landing shoulder.H-4 profile per 18¾″ system to allow wide range of BOP stacks. Run BOP stack and marine riser N/A N/A 18¾″ system or smaller 6″ minimum ID Drill 8″ hole Fluid BOP Run 6″ liner Fluid BOP Drill 8″ hole Fluid BOP Run 6″ liner Fluid BOP Drill 8″ hole Fluid BOP Run 6″ liner Fluid BOP Drill 8″ hole Fluid BOP Run 6″ liner and lower Fluid BOP completion with LTIV Run 5″ upper completion and LTIV Fluid/BOP expand onto the 6″ liner Set casing plugs Casing plug Fluid Tree Installation Alternatively, install the tree at the same time as the WH housing and drill thru tree. Retrieve BOP Casing plug Fluid Run HXT Casing plug Fluid Run BOP/LRP Casing plug Fluid LRP used in FIGS. 12-14 Completion Drill out/remove casing plugs Fluid LRP Drill 8″ hole N/A N/A Drill into formation Run 6″ liner and lower N/A N/A Assumes LTIV That can be completion with LTIV opened by overpressure or cyclic pressure Pull HXT bore protector N/A N/A Run 5″ upper completion N/A N/A Assumes that no packer is (outer tubing) and expand used onto the 6″ liner Run CTH, lock and test LTIV Fluid/LRP/ Assumes no SSTT needed. CTH CTH run on CT installation string, FIGS. 1, 6, 8 Flow Test Circulate to lighter fluid LTIV CSV Open CSV. Close when complete Overpressure the LTIV and PMV PWV Flow test via PBV and ITT, flow test the well CSV WOV FIGS. 1-11. Disconnect/drive USV LSV off by closing HXT values

no SSTT needed Isolate well at HXT USV LSV Close PMV and PBV Run ITC N/A N/A Run CTH 2ary lockdown N/A N/A Maybe unnecessary Pull BOP/LRP USV LSV Assumed acceptable as seals independently testable and on different seal bores. LRP use for FIGS. 12-14 Install controls cap by ROV N/A N/A Produce to flow lines USV LSV Open PMV and PWV Tubing access workover with BOP Pull controls cap N/A N/A Pull ITC N/A N/A Run LRP/ USV LSV BOP FIGS. 10, 11 18¾″ or BOP + marine riser smaller. 9″ min. ID. LRP FIGS. 12-14 Run ITT N/A N/A Circulate the well to kill weight Fluid LRP Open CSV. Close BOP rams on the ITT and circulate via choke/kill, FIGS. 1-11 Pull CTH Fluid LRP Open USV, LSV, FIGS. 10-14 Replace CTH Fluid LRP Circulate the well to light weight USV LSV Pull ITT N/A N/A Run ITC N/A N/A Pull BOP slack + USV LSV marine riser/LRP Install controls cap N/A N/A Tubing access workover with LWI Vessel Similar to above Outer tubing retrieval workover with BOP Assumed to be impossible due to tubing being expanded onto previous casing

[0053] FIGS. 15-18 are highly schematic half-sectional representations of a casing program that may be used with the wellhead housing 11 of the previous figures. FIGS. 15 and 16 are prior to tree installation; and FIG. 18 shows the tree 10 installed. Initially, a foundation is established using conductor casing 146, for example a 13⅜″ conductor or larger. The size of the LP housing and foundation is substantially independent of the size of the rest of the system.

[0054] A hole section is then drilled, a first casing section 100 is run and cemented and the wellhead housing 11 established. This may be of small diameter (21.6 mm, 8½″ drift). A further hole section is then drilled and an expandable casing section 148 run, cemented and expanded to the bore diameter of the first casing section 100. Expansion seals the casing section to the previously installed casing without the use of packers or the like. Methods for installing expandable tubulars are known in the art and will not be further elaborated here. The expansion pig may be run either from the top down or from the bottom up. However, the bottom up method is preferred, as then no hangers are needed.

[0055] Drilling continues and as many further casing sections 150, 152 as may be needed to reach the reservoir 154 are installed successively. All casing sections are expanded to the bore diameter of the initial section 100 (e.g. 6″), to produce a parallel sided well. When needed, the BOP 68 is installed on the wellhead housing 11. All casing sections are capable of withstanding the reservoir pressure.

[0056] Drilling is continued into the reservoir 154 as shown in FIG. 16 and a liner section 156 is installed and expanded to the casing diameter. The outer tubing string 98 is then run and expanded (preferably using the bottom up method) into sealing contact with the liner 156, casing and wellhead 11. Therefore no tubing hanger or packers are needed to support the tubing 98 and seal it in the wellhead housing 11: see FIG. 17. Also, the final top location of the tubing is not accurately predictable due to axial shrinkage during radial expansion. The liner 156 is perforated and a liner top isolation valve 160 or similar isolation device installed. Also shown in FIG. 17 is a tree stab 158 for sealing the tree 10 to a corresponding pocket in the wellhead housing 11.

[0057]FIG. 18 shows the tree 10 attached to the wellhead housing 11 in place of the BOP and the BOP reinstalled on the tree. The coiled tubing string 14 and coiled tubing hanger 12 is then run on the installation string 32 and landed in the tree 10. The coiled tubing string 14 may be used to carry downhole instrumentation, chemical injection and gas lift mandrels 162, 164, ESP's, separation equipment and the like, as discussed above, as well as any required service lines. These may be secured to the coiled tubing exterior as shown in FIGS. 3 and 4. Preferably however they are enclosed within the coiled tubing bore as indicated in FIGS. 1, 2 and 5-14. FIG. 19 is a diagrammatic cross-section through the coiled tubing, showing two fluid containing service lines 166, 168 and an electrical or optical service line 170.

[0058] FIGS. 20-22 show an alternative casing program. Again no casing hangers are required at the wellhead housing 11 and each casing section is capable of withstanding the reservoir pressure. The casing sections are each expanded into seating contact with the previously installed section, but are of successively smaller diameters. For example a 30″ conductor casing 146 may be used, with the other casing diameters (when expanded) as follows:

100:9⅝″; 148:8⅝″; 150:7⅝″; 152:6⅝″

[0059] Referring to FIG. 21, the final well section is drilled into the reservoir 154 and a (for example) 5⅝″ liner 156 and liner top isolation valve are 160 installed. The liner is expanded into sealing contact with the lowermost casing section 152.

[0060] As shown in FIG. 21, the outer tubing string 98 is run on a completion riser 174 and expanded at its lower end onto the production liner 156. The tubing string 98 is suspended from an outer tubing hanger 172 landed, sealed and locked down in the wellhead housing 11. No production packer is needed.

[0061] There are several possible methods of setting the outer tubing hanger 172 and facilitating the expansion of the outer tubing 98 onto the liner 156. The preferred methods are based on the “top down” expansion principle. This is better for this particular well construction due to the tapering casing strings. The outer tubing 98 only eliminates the tubing/production casing annulus at the lower section. A “bottom up” approach is only readily usable if a correspondingly tapered outer tubing 98 is used. This is inconvenient due the number of trips required to set the different sizes of pig and the increased tubing costs at the top sections.

[0062]FIG. 22 shows a first setting method. The outer tubing hanger 172 is run on a tool 174 and drill pipe 176. The expansion pig 178 is attached to coiled tubing 180. The pig 178 is pumped down by pressurised fluid supplied through the drill pipe/coiled tubing annulus. The coiled tubing 180 provides a return path up the tool string. However there may be difficulties in running coiled tubing at the same time as drill pipe.

[0063] A preferred alternative is as shown in FIG. 23. The bores of the THRT 174 and of the running string 176 are made large enough to drift the pig 178. The pig is easier to install as the coiled tubing 180 can be run after the tubing hanger 172 has landed. The coiled tubing annulus again provides the pressurised fluid flow path for expansion of the outer tubing 98, and the coiled tubing bore the return path.

[0064] There are various options for the seal interface between the wellhead housing 11 and the tree 10. One consideration is the need to isolate the VX gasket from the produced fluids. FIG. 24 shows a wellhead/tree seal arrangement for a completion including an outer tubing hanger 172. A seal pocket is provided at the upper internal diameter of the wellhead housing to interface a seal stab 158 on the tree. This corresponds somewhat to the FIG. 17 arrangement. The tree seal stab 158 has a drift diameter that allows passage of the tubing hanger to the bore of the well. This arguably is a single barrier to the environment if the VX gasket is discounted.

[0065] Alternatively, a seal pocket may be provided at the upper inside diameter of the outer tubing hanger 172 to interface a seal stab 158 on the tree, as shown in FIG. 25. With this option, the outer tubing 98 must be installed prior to tree installation. However the arrangement is arguably closer to that found in a conventional christmas tree and may therefore more readily gain industry acceptance and/or regulatory approval.

[0066] The arrangement shown in FIG. 26 is similar to that shown in FIG. 24, but includes a further seal pocket at the wellhead housing 11 inside diameter, to interface a further seal stab 182 from the coiled tubing hanger 12 or another component to be located in the bore 15 of the tree 10. The arrangement shown in FIG. 17 may be modified likewise, so that the wellhead housing 11 accommodates a further seal stab e.g. from the coiled tubing hanger 12. FIG. 27 is similar to FIG. 26, except that the pocket for the further seal stab 182 is at the outer tubing hanger 172 upper inside diameter.

[0067] FIGS. 28-30 are diagrams of a third drilling program. Casing hangers are used in the wellhead housing 11 to suspend concentric casing strings 149, 151, 153 and production casing 157. Each string is successively landed and expanded into sealing contact with the next outer string, preferably using a top down method such as shown in FIGS. 22 or 23. Prior to expansion, a temporary annulus exists between a given casing string and the next outer casing string. This can be used for circulation/cementing. Packoffs are not needed due to the seal effected between the concentric strings. The expanded casing sizes may be as follows:

100:9⅝″; 149:7½″; 151:7″; 153:6½″; 157:6″

[0068] As shown in FIG. 29, outer tubing 98 is suspended in the wellhead 11 from tubing hanger 172. The tubing 98 is then expanded onto the production liner 157. Again the production liner has an isolation device such as a liner top isolation valve. No packer is needed and the tubing hanger 172 need not itself be sealed and locked to the wellhead housing 11. (The expanded outer tubing 98 is sealed to the production casing 157).

[0069]FIG. 30 is a diagram showing the outer string hanger 172 and casing hangers 186, 188, 190, 192 for the successive casing strings 149, 151, 153, 157, landed in the (consequently elongated) wellhead housing 11. An interface with the tree seal stab 158 is also shown. Modification is of course possible in accordance with any of FIGS. 25-27. 

1. A completion system comprising a christmas tree (10) mounted on a wellhead housing (11), a tubing hanger (12) landed in the tree or wellhead housing, the wellhead housing being mounted on a casing string (100) and a first tubing string (14) being suspended from the tubing hanger (12) within the casing string; characterised in that, in use, a portion of the annulus defined between the first tubing (14) and the casing (100) serves as a production bore and the tubing (14) serves as a well service conduit; a second tubing string (98) being expanded into sealing engagement with the casing string (100) over at least a portion of their lengths, and the first tubing string being connected to a service/circulation conduit (48) in the Christmas tree (10).
 2. A completion system as defined in claim 1 characterised in that the entire length of the second tubing string (98) is expanded into contact with the casing string (100).
 3. A completion system as defined in claim 2 characterised in that the second tubing string (98) is supported without the use of a tubing hanger and/or packers.
 4. A completion system as defined in claim 1 characterised in that the second tubing string (98) is suspended from a hanger (172) supported in the wellhead housing (11).
 5. A completion system as defined in any preceding claim characterised in that said annulus is connected to one or more production flow control valves (36, 38) in the tree (10).
 6. A completion system as defined in any preceding claim characterised in that the first tubing string (14) is connected to one or more flow control valves (20, 50, 64).
 7. A completion system as defined in any preceding claim characterised in that the first tubing (14) is coiled tubing.
 8. A completion system as defined in any preceding claim characterised in that the tubing hanger (12) is landed in the tree (10).
 9. A completion system as defined in any preceding claim characterised in that the tubing hanger (12) is landed and sealed in a vertically extending through bore (15) in the tree (10), a production conduit (34) intersecting the through bore (15).
 10. A completion system as defined in claim 9 characterised in that a production master valve (36) and a production wing valve (38) are provided in the production conduit (34).
 11. A completion system as defined in claim 9 or 10 characterised in that a production bypass conduit (44) extends through the tubing hanger (12), between the tubing annulus and the through bore (15) above the tubing hanger (12).
 12. A completion system as defined in claim 11 characterised in that the production bypass conduit (44) and/or the through bore (15) above the tubing hanger is closeable by at least one removable barrier element (86, 122, 124).
 13. A completion system as defined in claim 12 characterised in that the at least one removable barrier element comprises a swab valve (122, 124).
 14. A completion system as defined in any of claims 11-13 characterised in that an installation test tool (18) may be coupled between the tubing hanger (12) and an installation string (32), a conduit (56) in the installation test tool communicating between the production bypass conduit (44) and a riser conduit (58) in the installation string (32).
 15. A completion system as defined in claim 14 characterised in that, in production mode, the production bypass conduit (44) is sealed by an internal tree cap (86) installed in the through bore (15) in place of the installation test tool (18).
 16. A completion system as defined in any of claims 9-15 characterised in that a service/circulation conduit (48) intersects with the through bore (15) and in use the tubing (14) interior communicates with the service/circulation conduit (48).
 17. A completion system as defined in claim 16 characterised in that the tubing hanger (12) comprises a side outlet (61) in communication with the first tubing (14) string interior and with the service/circulation conduit (48) when the tubing hanger (12) is landed in the tree (10), so as to define a service/circulation flow path extending from the upper end of the first tubing string interior out of the tree.
 18. A completion system as defined in claim 17 characterised in that an installation test tool (18) may be coupled to the tubing hanger (12) and comprises a side outlet (61) in communication with the first tubing (14) string interior and with the service/circulation conduit (48) when the tubing hanger (12) is landed in the tree (10), so as to define a service/circulation flow path (60, 61, 48) extending from the upper end of the tubing interior out of the tree (10).
 19. A completion system as defined in claim 18 characterised in that, in production mode, the installation test tool (18) is replaced by an internal tree cap (86) comprising a side outlet (61) in communication with the tubing (14) interior and with the service/circulation conduit (48), so as to define said service/circulation flow path.
 20. A completion system as defined in any of claims 17-19 characterised in that the service/circulation flow path (60, 61, 48) includes a central service/circulation valve (20).
 21. A completion system as defined in claim 20 characterised in that the service/circulation flow path includes a service/circulation wing valve (50).
 22. A completion system as defined in any of claims 16-21 characterised in that a workover conduit (62) extends from the service/circulation conduit (48) and intersects the through bore (15) above the tubing hanger (12).
 23. A completion system as defined in claim 22 characterised in that the workover conduit (62) contains a workover valve (64).
 24. A completion system as defined in claim 22 or 23 characterised in that an installation test tool (18) may be coupled to the tubing hanger (12) and comprises a lower end sealable within the through bore (15) below the workover conduit intersection and an upwardly extending spool (66) engageable by pipe rams (70) of a BOP (68) to provide communication between the workover conduit (62) and a choke or kill line (72) of the BOP.
 25. A completion system as defined in any of claims 16-21 characterised in that a workover conduit (62) extends from the service/circulation conduit (48) upwardly through the tree (10) for connection to a lower riser package (128).
 26. A completion system as defined in any of claims 9-15 and 16-25 characterised in that a crossover conduit (45) extends between the production conduit (34) and the service/circulation conduit (48).
 27. A completion system as defined in claim 26 characterised in that the crossover conduit (45) contains a crossover valve (47).
 28. A completion system as defined in any preceding claim, characterised in that an upper end of the tubing hanger (12) comprises one or more remote matable coupler parts (26) for connecting downhole service lines (28, 102) to corresponding coupler parts (26) in a tree cap (86) or installation test tool (18).
 29. A completion system as defined in any of claims 1-28 characterised in that the tubing hanger (12) interfaces with a horizontal penetrator (126) provided in the tree (10) for making an external connection to downhole service lines (28).
 30. A completion system as defined in claim 28 or 29 characterised in that the tubing hanger (12) is formed from separable upper (12 a) and lower (12 b) parts, downhole service lines being preassembled to coupler parts (112) provided in the lower tubing hanger part (12 b), co-operating coupler parts (112) being provided in the upper tubing hanger part (12 a).
 31. A completion system as defined in any preceding claim characterised in that an annular stab connector (158) extends from the christmas tree (10) for reception in the wellhead housing (11) or a further tubing hanger (172) received therein.
 32. A completion system as defined in any preceding claim characterised in that an annular stab connector (182) extends from the tubing hanger (12) for reception in the wellhead housing (11) or a further tubing hanger (172) received therein. 